The present invention relates to a process for removing sulfur from a sulfur-containing gas using a particulate solid which contains alumina in a form which reacts with sulfur compounds in the gas to form a solid compound in the particulate solid, and forming hydrogen sulfide using sulfur in the solid compound. In one aspect, the invention relates to removal of sulfur compounds from fluid catalytic cracking regenerator flue gas. In another aspect, the invention relates to removal of gaseous sulfur compounds from stack gases and tail gases formed during hydrocarbonaceous fuel combustion or gas treating operations, and forming hydrogen sulfide using the sulfur.
The desirability of removing sulfur compounds from various sulfur-containing gases is well known. This is particularly the case when it is desired to discharge such gases into the atmosphere. Concern with atmospheric pollution has imposed limits on the amount of gaseous sulfur compounds which can be discharged directly into the atmosphere in flue gases, tail gases and stack gases. For example, sulfur-containing gases result from such operations as fossil fuel combustion, Claus-type gas desulfurization, and regeneration of catalysts employed in petroleum refineries. Waste gases from such operations are often passed into the atmosphere. It is thus desirable to keep the sulfur content of these gases at a low level. Many of the methods previously proposed for reducing and controlling the amount of sulfur in such gases are uneconomical for the intended use. Such methods can substantially increase the cost of energy obtained from fossil fuel combustion and the cost of petroleum products produced in refineries in which sulfur emission controls are necessary.
Modern catalytic hydrocarbon cracking systems use a moving bed or a fluidized bed of a particulate catalyst. The cracking catalyst is subjected to a continuous cyclic cracking reaction and catalyst regeneration procedure. In a fluidized catalytic cracking (FCC) system, a stream of hydrocarbon feed is contacted with fluidized catalyst particles in a hydrocarbon cracking zone, or reaction zone, usually at a temperature of about 800.degree.-1100.degree. F. The reactions of hydrocarbons in the hydrocarbon stream at this temperature result in deposition of carbonaceous coke on the catalyst particles. The resulting cracked, or processed, hydrocarbon stream is thereafter separated from the coked catalyst and withdrawn from the cracking conversion zone. The coked catalyst is then stripped of volatiles and passed to a catalyst regeneration zone. In the catalyst regeneration zone, the coked catalyst is contacted with a gas containing a controlled amount of molecular oxygen to burn off a desired portion of coke from the catalyst and simultaneously to heat the catalyst to a high temperature desired when the catalyst is again contacted with the hydrocarbon stream in the cracking zone. The catalyst is then returned to the cracking zone, where it vaporizes the hydrocarbons and catalyzes hydrocarbon cracking. The flue gas formed in the catalyst regeneration zone, which contains the combustion products produced during burning of the coke, is separately removed from the regeneration zone. This flue gas, which may be treated to remove particulates and carbon monoxide from it, is normally passed into the atmosphere.
The conventional type of FCC regeneration operation currently employed in most FCC systems is an incomplete combustion mode of operation. In such conventional systems, referred to herein as standard regeneration systems, a substantial amount of coke carbon is left on the catalyst particles when they are removed from the FCC regeneration zone and recycled to the FCC conversion zone. Typically, regenerated catalyst removed from an FCC regeneration zone contains a substantial amount of coke carbon, i.e., more than 0.2 weight percent carbon, and usually contains about 0.25 weight percent to about 0.45 weight percent carbon when a standard regeneration mode of operation is used. The flue gas removed from the FCC regeneration zone in a standard, incomplete regeneration operation is characterized by a relatively high carbon monoxide/carbon dioxide concentration ratio. There is a reducing atmosphere in much of the regeneration zone because of the presence of substantial amounts of unburned coke carbon and carbon monoxide in standard regeneration systems.
Removal of substantially all the coke carbon from FCC cracking catalyst during the regeneration operation has been difficult. Until recently, there has been little incentive to attempt to remove substantially all the coke carbon from the regenerated catalyst, i.e., to reduce the carbon content of regenerated catalyst below 0.2 weight percent, and preferably 0.1 weight percent, since even a fairly high carbon content has had little adverse effect on the activity and selectivity of amorphous silica-alumina catalysts previously used. Most of the FCC cracking catalysts now used, however, contain zeolites, or molcular sieves. The zeolite-containing catalyst have usually been found to have relatively higher activity and selectivity when their coke carbon content is relatively lower. An incentive has thus risen for attempting to reduce the coke content of regenerated catalyst to a very low level, below 0.2 weight percent.
Several methods have been recently suggested for removing substantially all the coke carbon from FCC cracking catalyst during regeneration. FCC regeneration systems using these methods normally involve complete combustion to carbon dioxide of substantially all the carbon in the coke in the catalyst within the FCC regeneration zone. Such systems are therefore referred to herein as complete combustion regeneration systems. Among the procedures suggested for use in complete combustion type FCC regeneration systems are (a) increasing the amount of oxygen introduced into the regeneration zone relative to standard regeneration, (b) increasing the average operating temperature in the regeneration zone, and (c) including various coke carbon oxidation promoters, such as Group VIII noble metals, in FCC cracking catalyst compositions to promote coke burnoff in the regenerator. Various solutions have also been suggested for the problem of afterburning of carbon monoxide in FCC regenerators, e.g., addition of extraneous combustibles or use of water or heat accepting solids to absorb carbon monoxide combustion heat from the flue gas.
The hydrocarbon feeds processed in commercial FCC units normally contain sulfur, herein termed feed sulfur. It has been found that about 2-10% or more of the feed sulfur in a hydrocarbon stream processed in an FCC system is invariably transferred from the hydrocarbon stream to the cracking catalyst, becoming part of the coke formed on the catalyst particles within the FCC cracking or conversion zone. This sulfur, herein termed coke sulfur, is eventually removed from the conversion zone on the coked catalyst which is sent to the FCC regenerator. Accordingly, about 2-10% or more of the feed sulfur is continuously passed from the conversion zone into the catalyst regeneration zone with the coked catalyst in an FCC unit.
In an FCC catalyst regenerator, sulfur contained in the coke is burned, along with the coke carbon, forming primarily gaseous sulfur dioxide and sulfur trioxide. These gaseous sulfur compounds become part of the flue gas produced by coke combustion and are conventionally removed from the regenerator in the flue gas.
Most of the feed sulfur is converted either to normally gaseous sulfur compounds, e.g., hydrogen sulfide, and carbon gaseous sulfur compunds, e.g., hydrogen sulfide, and carbon oxysulfide, or to gasoline boiling range organic sulfur compounds, in the FCC cracking zone. These fluid sulfur compounds are carried along in the processed hydrocarbon stream. About 90% or more of the feed sulfur charged to the cracking zone in FCC units is thereby continuously removed from the cracking zone in the stream of effluent processed hydrocarbons with 40-60% of this effluent sulfur being hydrogen sulfide. For this reason, provisions are conventionally made in petroleum refineries to recovery hydrogen sulfide from the processed hydrocarbon effluent. Usually, a very-low-molecular-weight off-gas vapor stream is separated from the liquid hydrocarbons in a gas recovery unit and is treated, as by scrubbing it with an amine solution, in order to remove the hydrogen sulfide from the off-gas. Removal of sulfur compounds such as hydrogen sulfide from the processed hydrocarbon effluent from an FCC unit cracking zone is relatively simple and inexpensive, especially as compared to removal of sulfur oxides from an FCC regenerator flue gas by conventional methods.
It has been suggested to reduce the amount of sulfur in FCC regenerator flue gas in commercial units, when necessary, by either: (1) desulfurizing the hydrocarbon FCC feed in a separate desulfurization unit to reduce the amount of feed sulfur prior to processing the feed in the FCC unit; or (2) desulfurizing the regenerator flue gas itself, by a conventional flue gas desulfurization procedure, after the flue gas has been removed from the FCC regenerator. Both of the foregoing alternatives require elaborate additional processing operations and necessitate substantial additional capital and utilities expenses in a petroleum refinery. For this reason, the cost of processing high-sulfur feedstocks in FCC units is high. Yet, many of the petroleum stocks currently available for processing in FCC units have a high sulfur content. Thus, the inclusion of expensive extraneous equipment and procedures in refinery operations to reduce the amount of sulfur in the flue gas removed from an FCC unit is a major problem in the FCC art. Such additional extraneous procedures could be at least partially obviated if that part of the feed sulfur which is conventionally removed from the FCC regenerator as gaseous sulfur compounds in the flue gas could instead be removed from the FCC unit reactor as hydrogen sulfide along with the processed hydrocarbons. This portion of feed sulfur would then become simply a small addition to the much larger amount of feed sulfur already unavoidably present, as hydrogen sulfide and organic sulfur, in the stream of processed hydrocarbons. The small added expense, if any, of removing even as much as 5-15% more hydrogen sulfide from FCC reactor off-gas using already available hydrogen sulfide removal systems would be substantially less than the expense which would be incurred if separate feed desulfurization or flue gas desulfurization operation were instead used to control the amount of sulfur in the flue gas. Most, if not all, FCC reactor off-gas hydrogen sulfide recovery systems used with present commercial FCC units already have the capacity to remove additional hydrogen sulfide from the off-gas. Present off-gas hydrogen sulfide removal facilities could thus handle the additional hydrogen sulfide which would be added to the off-gas if feed sulfur charged to the FCC system were substantially all removed from the system as hydrogen sulfide in the FCC reactor off-gas, rather than having a portion of feed sulfur removed from the unit in the FCC regenerator flue gas. It would accordingly be desirable to direct substantially all feed sulfur into the processed hydrocarbon removal pathway from the reactor in order to reduce the amount of sulfur in the FCC regenerator flue gas, rather than either: (1) desulfurizing the hydrocarbon feed prior to charging it to the FCC conversion zone, or (2) subsequently desulfurizing the regenerator flue gas after it is removed from the FCC regenerator.
Alumina has been a component of many FCC and other cracking catalysts, but primarily in intimate chemical combination with silica. Alumina itself has low acidity and is undesirable for use as a cracking catalyst. As a cracking catalyst, alumina is nonselective, i.e., the cracked hydrocarbon products recovered from an FCC or other cracking unit using an alumina catalyst would not be the desired valuable products, but would include, for example, relatively large amounts of light paraffin gases. Silica, as such, is also low in acidity and is a poor cracking catalyst. Physical mixtures of alumina and silica have likewise been found to be low in acidity and are poor cracking catalysts. On the other hand, chemically combined alumina and silica, e.g., alumina-silica cogels and molecular sieves, or zeolites, have been found to be quite high in acidity, and are used in most, if not all, present commercial FCC catalysts.